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DEPARTMENT OF PETROLEUM & ENERGY

PETROLEUM DIVISION

PETROLEUM POLICY HANDBOOK

NOVEMBER 2005



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PREPARED BY THE

POLICY BRANCH, PETROLEUM DIVISION DEPARTMENT OF PETROLEUM AND ENERGY PO BOX 1993 PORT MORESBY PAPUA NEW GUINEA TELEPHONE: (+675) 322 4200 FAX: (+675) 322 4222 NOVEMBER 2005

Updated by Roger Avinaga Assistant Director Petroleum Policy Branch [email protected]

mailto:[email protected]�



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TABLE OF CONTENTS PART 1. SUMMARY OF PETROLEUM POLICIES 1 PART 2. LICENSING 8 PART 3. FISCAL REGIME 15 PART 4. PETROLEUM AGREEMENT 22 PART 5. TRADITIONAL LAND OWNERSHIP AND LANDOWNER BENEFITS 26 PART 6. ENVIRONMENTAL GUIDELINES AND REQUIREMENTS 29


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PART 1: SUMMARY OF PETROLEUM POLICIES 1.1 Philosophy The Independent State of Papua New Guinea (PNG) considers the development of the State's petroleum resources to be amongst its highest priorities. The State is committed to the development of these resources in a way, which maximises the benefits of petroleum production to the people of PNG, while minimising social, environmental and economic costs. At the same time the State recognises the need to develop its petroleum resources in conjunction with international oil companies. It further recognises that to attract major overseas investors, it must offer a stable economic and political environment, which allows the investor the opportunity to make a reasonable return on exploring for and developing oil and gas resources in Papua New Guinea. 1.2 Type of Government Westminster Style unicameral Parliamentary Democracy. 1.3 Ownership of Resources Petroleum resources, onshore and offshore, belong to the State, which licenses others to explore for, recover and sell or otherwise dispose of petroleum so recovered. 1.4 Key Legislations A number of key legislations govern the exploration, development, processing and transportation of petroleum in Papua New Guinea. 1.4.1 Oil And Gas Act 1998 (As Amended) The Oil and Gas Act 1998 (as amended) is the principal legislation that governs petroleum exploration and development and State Entitlement and Benefits in Papua New Guinea. It spells out the role and purpose of the legislation in key areas including the exploration, development, processing, transportation and makes provisions for grant of benefits to traditional landowners, Local Level Governments and Provincial Governments arising from the production, processing and transportation of petroleum in Papua New Guinea. (This Policy Handbook is primarily derived from the Oil and Gas Act and any changes to the Act take precedence.) 1.4.2 Other Key Legislation

• Income Tax Act 1959 (as amended), Division 10 – Mining, Petroleum and Designated Gas Projects

• VAT Legislation and Stamp duty legislation • Environmental Act 2000

● Environmental Contaminants Act (Chapter 368) ● Water Resources Act (Chapter 205)


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• Mineral Resources Pty Ltd. (Privatization) Act 1996 • Resource Contracts Fiscal Stabilization Act 2000

• Organic Law on Provincial Governments and Local Level Governments.

In addition, companies are required to enter into an agreement with the State, called a Petroleum Agreement. Most companies enter into a Petroleum Agreement with the State prior to drilling the first exploration well in the licence area. The Petroleum Agreement must be entered into before the grant of a petroleum development licence. In the case of a gas project, the relevant agreement is a Gas Agreement. 1.5 Macroeconomic Policy The Government has aimed to maintain a stable economic environment. Generally, Papua New Guinea is committed to policies of free enterprise, free trade and convertibility of currency. In particular, the State is committed to the currency provisions of the Petroleum Agreement, which guarantee the ability to retain earnings in foreign currencies, to make expenditures abroad, to service debt and to remit profits. 1.6 Fiscal Regime The primary instrument of the fiscal regime is income tax, In addition, royalties and development levies are payable, and the State has the right to purchase, at cost, up to 22.5% participating interest in petroleum development projects. 1.7 Significant Incentives Through Reduced Petroleum Operations Rates In 2003, the fiscal regime has been substantially revised to encourage petroleum development. By the industry’s judgment, the previous fiscal changes introduced in 2000 did not improve the country’s hydrocarbon fiscal regime. The presence of excess taxes such as the Additional Profits Tax was seen as making the fiscal regime “tough”. The petroleum industry in PNG has been seeking better fiscal terms. They have argued that the level of exploration and production had been declining in the country. Taking these concerns into account, the Government recently introduced in the 2003 Budget new fiscal incentives to rejuvenate petroleum exploration and production activities in PNG under special terms called “incentive rate petroleum operations”. These fiscal incentives are anticipated to send a very strong signal to the oil and gas sector already established in the country and to the international industry. The 2003 fiscal incentives cover: - 1.7.1 Abolition of Additional Profits Tax The new incentive sees the abolition of the APT on new petroleum and gas projects. That removes the first and second tiers and the respective rates at which APT has been previously applied. APT has been seen as a real disincentive, where APT was triggered at a relatively low rate of return for a project developer. This was considered disproportionate to the risks assumed by the project developer.


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1.7.2 Corporate Tax Reduced to 30% Under the new incentive provided for petroleum activities and operations, the corporate tax rate has been reduced from the present 45% to 30%. Not only will the new tax encourage exploration activities but ensure the development of marginal discoveries that have been previously declared economically not viable to be developed.

To qualify for the special reduced corporate tax rate, companies need to be granted a Petroleum Prospecting Licence within the designated period of 1st January 2003 to 31st December 2007 from which a PDL is granted on or before 31st December 2017. The companies that are entitled to the incentive rates have to commit to a rigorous and active exploration work programme, which will be strictly enforced and failure to fulfill the programme could lead to a licence being cancelled. 1.7.4 Incentive Petroleum Operation Rates Summary APT:

Henceforth APT will not apply except in respect of operations, which come under the Gas Agreement signed in Port Moresby on 6th June 2002.

Corporate Tax: For petroleum projects granted PPL in the period 1st January 2003 to 31st December 2007 and PDL granted on or before 31 December 2017, Corporate Tax has been reduced from 45% to 30%

In addition to the incentive rates, Royalty and Development Levies (both calculated at 2% of well value of petroleum) will also be payable by the licensees. Fiscal stability terms are also available to petroleum companies. They attempt to ensure that fiscal terms, particularly tax rates, remain the same 1.8 Pre-2003 Fiscal Regime for Petroleum Operations In 2000, a major review of the fiscal regime applying to resource projects (mining, petroleum and gas) was undertaken, which resulted in substantial legislative changes. The fiscal regime shown below is rates applicable to the petroleum projects already in operation before 1 January 2003. 1. 8. 1 Petroleum and Gas Fiscal Terms for pre-2003 Projects

Royalties:

2% of wellhead value, which is treated as a tax credit, provided development levies are payable to the affected Provincial Government.

Development Levies: 2% of wellhead value, which is treated as a normal tax deduction.

Income tax:

Petroleum operations attributable to a new petroleum project are 45% of the taxable income: Petroleum operations, which began production before 2000 Tax Review is 50% of taxable income. Gas operations are 30% of the taxable income.

Dividend withholding tax:

None.


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Additional profits tax:

A two tier APT system. First tier: has a 15% accumulation rate with 20% tax rate; the second tier has a 20% accumulation rate with 25% tax rate.

Past exploration expenditure:

Exploration expenditure in the 20-year period prior to project development is deductible. Written off against project income, on diminishing value basis, using a divisor of 4.

Current exploration expenditure:

25% of current year exploration expenditure in any license is deductible, limited to 10% of total tax (otherwise) payable.

Capital Expenditure:

Long term assets: written off on straight-line basis using divisor of 10. Short term assets: written off on a diminishing balance basis-using divisor of 4.

Value Added Tax: Not applicable to oil and gas projects. Debt to equity ratio: 3:1 (for income tax purposes) Tax losses carry forward: Has been increased from seven to twenty years.

Import Duties: Tax rates applicable are those set to apply at end of the tariff reform programme

1.9 State Equity Entitlement The State has the option to acquire up to a 22.5% equity interest in any petroleum development. Where it does so, 2% of this interest is held for the benefit of landowners in the project area. The price payable by the State is its share of sunk costs defined by reference to Allowable Exploration Expenditure. As from the 1st of January 2003, if the State exercises its option, it is exercised immediately. If the State chooses not to exercise its option, the option will lapse. 1.10 Licences The Oil & Gas Act 1998 provides for five different types of licences: petroleum prospecting licences (PPLs) for exploration; petroleum development licences (PDLs) for petroleum developments; petroleum retention licences (PRLs) for discovered gas reserves which are considered sub-economic; pipeline licences (PLs); and petroleum processing facility licences (PPFLs). Features of these licences are as follows:

1.10.1 Petroleum Prospecting Licences

Term:

6 years, plus one 5 year extension

Relinquishment obligations:

50% of initial size, less the area of any PRLs, on extension

Maximum size:

Usually 60 graticular blocks, each approximately 9 km. by 9 km.

Application fee:

K10, 000


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Annual fees:

K500 for each graticular block on the anniversary of the licence. In the case where PPL is granted by extension: (1) K1, 000 per graticular block in the first year (2) K1, 500 per graticular block in the second year (3) K2, 000 per graticular block in the third year (4) K3, 000 per graticular block in the fourth year (5) K4, 000 per graticular block in the fifth year

Security deposit:

A bond in the form of either a cash deposit or bank guarantee of up to K1, 000,000.00 will be determined at the Department of Petroleum and Energy discretion

Surrender entitlement: Surrender without penalty permitted provided licence conditions have been met to that point

Work commitment:

Negotiable

1.10.2 Petroleum Development Licences

Term:

25 years, plus normally one 20 year extension or further 20 year extensions reasonably required to recover the maximum amount of petroleum

Application fee: K50, 000 Annual fee: K100, 000

1.10.3 Petroleum Retention Licences

Term: 5 years, plus two 5 year extension Relinquishment: None required Maximum size: May only include blocks in which a gas held on field

lies or adjacent blocks required for better administration

Application fee:

K10, 000

Annual fees:

K 30,000

Work commitment:

Negotiable

1.10.4 Pipeline Licences

Term:

25 years, plus normally one 20 year extension or further 20 year extension or lesser periods as the Minister thinks fit

Application fee: Annual fees:

K50, 000 0 to 10 km - K 10, 000 10 to 100 km - K 1, 000 per km 100 km or greater - K100, 000


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1.10.5 Petroleum Processing Facility Licences

Terms: Application fee: Annual Fees:

Licence would remain in force until cancelled by the Minister under section 138 of the Act or surrendered by the licensee under section 137 of the Act. K50, 000 K100, 000


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PART 2: LICENSING 2.1 Administration 2.1.1 The Minister The Minister responsible for granting licences is the Minister for Petroleum and Energy, who is advised by the Petroleum Advisory Board. The Department of Petroleum and Energy is responsible for the administration of the Oil & Gas Act. The officer principally responsible is the Director appointed under the Oil and Gas Act by the Minister. This is normally the Secretary of the Department of Petroleum and Energy. The Petroleum Division of the Department handles the day-to-day administration of petroleum activities. 2.1.2 The Petroleum Advisory Board The Petroleum Advisory Board is made up of the Director, Oil and Gas Act of DPE who shall be the Chairman, and not more than six other members as prescribed: Secretary of the Department of National Planning, Secretary of the Department of Treasury, Secretary of the Department of Provincial and Local Level Government, Director of Petroleum Division, Chief Inspector appointed pursuant to Section 151 of the Oil and Gas Act and Director of Investment Promotion Authority. The Board meets from time to time to make recommendations to the Minister on matters relating to petroleum, including the grant of licences, variations to licence conditions, and the approval of petroleum prospecting licence work programmes at the end of the second and fourth years of the licence period. 2.2 Petroleum Prospecting Licence Applications Explorers may apply for petroleum-prospecting licences in Papua New Guinea at any time provided the graticular blocks have not been reserved by the Minister.

Applications should comply with the following: 2.2.1 Contents

When granting a prospecting licence the Minister must be satisfied that the applicant has a coherent exploration strategy for the licence area as well as the technical and financial resources to carry out the required work programme. The following information should therefore be included in an application;

(a) the full name of the individuals or companies who are to be the licence holders;

(b) if more than one individual or company is to hold the licence, the

respective participating interests and the identity of the operator; (c) the specific blocks over which a licence is being sought, and a

sketch map indicating their position; (d) an outline of the technical resources of the applicant, including

prior experience in Papua New Guinea and descriptions of similar exploration programmes carried out elsewhere, as well as


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the resumes of key individuals to be involved in the proposed programme;

(e) details of the financial and asset resources of the applicants

including the most recent financial statements and where appropriate outlines of similar ventures undertaken;

(f) detailed work and expenditure programmes proposed for the first

two years of the initial licence period; (g) indicative work and expenditure programmes proposed for the

final four years of the initial licence period; (h) a synopsis of the technical rationale used in developing the work

programme proposed; (i) postal, fax and email addresses of the applicants; and (j) any other information which might be relevant to the application.

The application fee of K10, 000, must also accompany the application

PORT MORESBY Papua New Guinea

For courier deliveries, documents should be delivered to:

Elanese Road Newtown, PORT MORESBY, PNG

2.3 Processing of Petroleum Prospecting License Applications The formalities for the consideration of PPL applications are set out in the Oil & Gas Act 1998. These are summarised below:

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2.2.2 Delivery of Applications

The application (with three copies) should be addressed to:

The Director c/- The Petroleum Registrar Department of Petroleum and Energy PO Box 1993

(a) After receipt of the application, notice of the application is published in the National Gazette. Objections received more than one month after gazettal will not be considered.

(b) The Petroleum Advisory Board meets sometime after the last day for objections.

(c) After hearing the recommendations of the Petroleum Advisory Board, the Minister will inform the applicant that: (i) he is prepared to grant the licence; or (ii) he will not grant a licence.


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(d) If the Minister is prepared to grant the licence, he will serve an instrument on the applicant containing:

(i) notice that he is prepared to grant the licence; (ii) the conditions on which he is prepared to grant the licence (i.e. a

draft licence document); and (iii) the format and requirement for a bond to be executed by the

applicant giving security for compliance with the licence conditions, supported by security either in the form of a cash deposit or bank guarantee for the amount of K50,000.

(e) Within one month of receiving the above instrument (or up to 4 months

at the Minister's discretion) the applicant must: (i) request the Minister to grant the licence; (ii) lodge the security with the Director; and

(iii) pay the first annual fee.

(f) After the applicant has complied with these requirements, the Minister

will grant the licence subject to the stipulated conditions. 2.4 Eligibility to Hold Petroleum Prospecting Licences Petroleum Prospecting Licences may be held by:

(i) a natural person; (ii) a corporation incorporated under the Companies Act; or

(iii) a corporation registered as an overseas company under the Companies

Act. There is no impediment to a foreign company holding a licence directly, rather than through a local subsidiary. 2.5 Petroleum Prospecting Licence Conditions 2.5.1 Size of PPL

PPLs are usually limited to 60 blocks. A block is graticular section 5 minutes latitude by 5 minutes longitude (which is approximately 9 kilometres by 9 kilometres). Each block within a licence area must have at least one side in common with another block in the licence.

The Minister may, however, grant PPLs comprising up to 200 blocks where he is satisfied that special circumstances exist for his doing so.

2.5.2 Term of PPL

Initial grant is for a period of 6 years, subject to one extension of 5 years. A further extension of up to 5 years is permitted under certain circumstances, in respect of locations (i.e. declared discoveries).


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2.5.3 Relinquishment of Licence Area on Extension Upon extension of a PPL, 50% of the originally granted PPL may be retained plus any blocks that have been declared a location on which have become the subject of a petroleum retention license on application for such. 2.5.4 Work Programme

The extent of the work programme of a PPL is negotiable, and will depend on the circumstances of the licence, such as prospectively, location and proximity to petroleum facilities. A detailed work and expenditure programme for the first two years must be submitted with the application, with an outline for the remaining four years. A detailed programme for years 3 and 4 must be submitted before the end of the second year, and for years 5 and 6 before the end of the fourth year. These must be acceptable to the Minister.

Appropriate variations to work commitments may be approved by the Minister at any time during the 3rd to 6th years of the licence period. 2.5.5 Licence Surrender

A licensee may surrender a licence without penalty if the licence conditions to that point have been met or if an acceptable case for doing so has been submitted to and accepted by the Minister.

2.5.6 Fees

The application fee is K10, 000. Fees in the first 6 years of the licence are K500 per graticular block per year. In subsequent years, following an extension, the fees per graticular block are:

Years Fees (Kina) Year 1 K1, 000

Year 2 K1, 500

Year 3 K2, 000

Year 4 K3, 000

Year 5 K4, 000

2.5.7 Security Deposit The licensee as security for compliance with licence conditions is required to lodge a security deposit. This is normally by way of a bond either in cash or by a bank guarantee. This is usually set at K 50,000, but the Act provides for a bond of up to K 1 million, (S.142).


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2.5.8 Procedures Governing Discoveries A Licensee is required immediately to notify the Director of any discovery of petroleum.

When petroleum has been discovered, the Minister may, on the request by the Licensee or otherwise, declare the block in which petroleum has been discovered, and such other adjoining blocks as the law permits, to be a Location.

Where a Location has been declared, the Minister may direct the licensee to carry out such investigations and studies, as the Minister thinks proper. 2.5.9 Assignment and Dealings

Changes to interests in licences and transfers in all types of petroleum licences are permitted, subject to the Minister’s consent. Any change or transfer without such consent is void. 2.6 Petroleum Retention Licences Petroleum retention licences are available for discoveries of gas, which are not considered to be currently commercially viable, but which are expected to become commercially viable in time. The applicant must satisfy the Minister that the blocks in respect of which a PRL is sought contain a gas field or part of a gas field. The Minister will not normally grant petroleum retention licence in respect of a field, which contains quantities of oil, considered to be commercially recoverable.

A retention licence is granted for an initial term of 5 years, with the possibility of two 5-year extensions.

A work programme must be agreed with the Minister. This will normally involve work with a view to commercialisation of the resource, including marketing and feasibility studies.

The application fee for a PRL is K10, 000. Annual fees are K30, 000. 2.7 Petroleum Development Licences

A PDL grants the licensee exclusive rights to carry on operation for the recovery of petroleum. However there are instances where a non PDL-holder may produce petroleum from his licence block, e.g., a PPL-holder conducting Extended Well Tests to appraise petroleum pool in his licence blocks.

2.7.1 Grant of a PDL

The holder of a PPL or a PRL over the area of a discovery has priority rights to apply for and be granted a PDL in respect of that discovery. Persons who do not hold a PPL or a PRL over that area may not apply for a PDL if another person holds a PPL or PRL over that area.

Applications for a PDL must be accompanied by detailed proposals for development of the petroleum resource. The Director may require additional proposals to be submitted.


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Before granting a PDL, the Minister must have considered a report from the PAB and where (if) available the relevant Cost-Benefit Analysis by the National Economic and Fiscal Commission. The Minister must be satisfied that the applicants’ proposals for development:

(i) will achieve maximum efficient recovery without wastage by

applying good oilfield practice; and (ii) will not interfere with rights of licensees in adjacent tenements

over common petroleum pools. (iii) will not discriminate against others wanting to access strategic

pipelines or strategic petroleum processing facilities involved in the proposals; and

(iv) will provide adequately for the protection of the environment and the welfare of the people of the area; and

(v) has adequately identified customary land owners; and (vi) will promote viable domestic utilisation of petroleum and

petroleum products to the extent reasonably possible; and (vii) will “otherwise” be in the best interest of the people of Papua New

Guinea. (viii) have duly considered coordinated development of any adjacent

petroleum discoveries

2.7.2 Term of a PDL

PDLs are granted for 25 years, with normally one extension of up to 20 years possible for the maximisation of petroleum recovery.

2.7.3 Fees for PDL

The application fee for a PDL is K50, 000. Annual Fees are K100, 000. 2.8 Pipeline Licenses A pipeline licence is required for the construction and operation of any petroleum pipeline outside of the area of a PDL. Where the pipeline is for the carriage of petroleum from a declared location, the holder of a PDL over that location has a prior right to be granted the pipeline licence. A pipeline licence is granted for a period of 25 years, with 20-year extensions possible subject to the term of the PDL or PDLs from which petroleum is being conveyed. Fees for a pipeline licence are K50, 000 on application. An annual fee is payable in the manner set out by Section 157(2)(e) of the Act, i.e. the greater of –

(i) K10, 000.00; and (ii) the lesser of –

(A) K100, 000.00; and (B) K1, 000.00 multiplied by the number of entire kilometres

in the length of the pipeline.


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PART 3: FISCAL REGIME 3.1 Introduction The Papua New Guinea fiscal regime for petroleum development is designed to provide an equitable sharing of revenue between the State and developers. It:

• provides investors with a fair and reasonable return on capital in the event of commercialization of a discovery;

• provides a stable and predictable fiscal framework for oil companies

contemplating investment in Papua New Guinea; • recognizes the high cost and risks of exploring for petroleum in Papua

New Guinea; and • is flexible enough to make less profitable but still economically desirable

projects attractive to the private investor. 3.2 Legal Basis Taxation provisions applied to the income arising from petroleum operations are contained in the Income Tax Act 1959 (as amended), Division 10 – Mining, Petroleum and Designated Gas Projects. Royalty and development levy obligations are contained in the Oil & Gas Act 1998, Sections 159 & 160, and the Income Tax Act, Division 10.G. Petroleum operation being zero-rated, are not subject to VAT. The transfer of petroleum licences is subject to stamp duty under the Stamp Duty Act.

Additional elements, including obligations as to State Equity Entitlement, are contained in the Petroleum Agreement that may be executed between the State and the Oil Companies. 3.3 Description of Taxation Regime This part describes the taxation regime applying to oil and gas projects generally in Papua New Guinea.

3.3.1 Income tax

Income tax is levied on taxable income from petroleum or gas operations. The rate of income tax is 50% of taxable income for all existing petroleum projects. As a result of the 2000 Tax Review recommendation, income tax was reduced to 45% for any new PDL granted prior to 1st of January 2003. Taxable income from a gas project is subject to income tax at 30%. Income tax taxable from petroleum operations has further been reduced from 45% to 30% under the new fiscal incentive introduced in 2003. The new incentive rate on petroleum operations will however, be applicable during the designated periods. To qualify for this incentive rate, oil companies need to be granted new Petroleum Prospecting Licences within the designated period of 1st January 2003 to 31st December 2007 and new Petroleum Development Licences evolving from these PPLs, to be granted on or before 31st December 2017.


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(i) Taxable Income

Taxable income from petroleum and gas operations is defined according to normal concepts and usage - gross revenue from petroleum operations less the following deductions: royalty and development levies (where applicable), allowances for the write off of past exploration and capital expenditure, interest deductions (but subject to a debt: equity ratio restriction), operating costs, and previous tax losses (if any) carried forward.

(ii) Interest Deductions

Interest is deductible from taxable income subject to the following:

(a) Interest during development is capitalized and written off as a deduction

over the life of the project according to the provisions of the Income Tax Act;

(b) for tax purposes, the ratio of debt to equity cannot exceed 3:1; and

(c) no deduction will be allowed for interest incurred by a petroleum

company prior to issue of a development license - i.e. interest is excluded from allowable exploration expenditure.

(iii) Exploration Expenditure

Under ring fencing principles, exploration expenditure is not automatically deductible. However, past exploration expenditure incurred anywhere in the area of a petroleum prospecting licence from which, a project is developed, within 20 years (but not before 1990 for oil and 1985 for gas) prior to the grant of a petroleum development licence for the project, is deductible against income derived from the project. The total of such expenditure is the allowable exploration expenditure of the project. The deduction allowed in each year is determined by dividing residual exploration expenditure by the number of years remaining in field life, or by four, whichever is less.

Pooling of current petroleum exploration expenditure incurred outside the petroleum project is allowed. From 2001 onwards, exploration expenditure incurred during the year may be transferred into a common exploration pool. An amount of up to 25% of the undeducted balance of the pool may be claimed as a deduction each year against income from the petroleum project. However the deduction may not result in tax payable being reduced by more than 10%. Exploration expenditure may subsequently be transferred from the pool into a resource development project as allowable exploration expenditure, in the event of a PDL arising from a PPL.

The Income Tax Act also has provisions permitting the transfer of unsuccessful exploration expenditure from a petroleum prospecting licence which has been surrendered or cancelled, or which expires, to become allowable exploration expenditure for a petroleum project elsewhere in Papua New Guinea. Also, if at the conclusion of a project there is undeducted residual exploration expenditure that too can be transferred to another project.


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(iv) Capital Expenditure

Capital expenditure is capitalized and written off over the life of the project. From 2001 onwards, capital assets are classified as being short term or long term assets. Long-term assets have an expected life of ten years or more. They are written off over ten years on a straight-line basis. The deduction allowable for short life assets, i.e., with an expected life of less than ten years, is calculated by dividing the residual capital expenditure by remaining field life or four, whichever is less. Alternatively, the taxpayer may elect to depreciate short life assets under the normal depreciation provisions of the Income Tax Act.

Allowable capital expenditure of a project includes interest on debt incurred after the grant of the petroleum development licence but before commencement of commercial production, provided the ratio of debt to equity does not exceed 3:1.

(v) Accelerated Depreciation

The Accelerated Depreciation provisions, which allowed additional exploration and capital deductions to be claimed in order to achieve a minimum return on capital invested, no longer apply since 2001.

(vi) Tax Loss (and exploration expenditure) Carry Forward

The tax loss carry forward period has been, since 2001, increased from seven years to twenty years. However, there are no carry back provisions. This means that losses, which have been written off under the old (7 year) provisions, cannot be reinstated. Exploration expenditure can similarly be carried forward for up to 20 years (increased from 11 years)

(vii) Additional Profits Tax

Additional profits tax (APT) is similar to a resource rent tax, (which exists in Australia and elsewhere) in that its objective is for the State to share in gains from a petroleum resource, which are in excess of what are considered reasonable and justifiable returns to the investor.

As stated earlier, as part of the incentives introduced in 2003, APT has been abolished for all projects except for operations, which come under the Gas Agreement signed in June 2002. APT is designed such that it becomes payable when a project’s ‘net cash receipts’ are positive. Net cash receipts are the sum of all revenue received less all cash payments for prior exploration, development costs and ongoing operating costs, including income tax payable. Initially, net cash receipts will be negative and will remain negative for as long as accumulated exploration, development or operating expenditure is greater than accumulated sales revenue. Moreover the annual ‘negative’ net cash receipts amount are increased or ‘uplifted’ each year by an ‘accumulation’ rate. This accumulation rate is designed to ensure that companies, before paying APT, recover their investment and also achieve a return on their investment, which is equal to the accumulation rate. (It may be appropriate to have this brief description of APT considering its limited application now)


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3.3.2 Project Basis of Assessment (“Ring Fencing”) Tax assessment is made on a project basis of assessment (“ring fencing”). A “project” for this purpose comprises the petroleum or gas operations conducted pursuant to a single petroleum development licence, unless a regulation provides otherwise. A regulation may prescribe that the petroleum operations of many licences comprise a single project, or that several projects are conducted under one licence. 3.4 Royalties Royalties are set at 2% of wellhead value of petroleum is payable to the State. Royalty is payable under Section 159 of the Oil & Gas Act 1998. It is treated as tax credit against assessable income in the case where development levies are also payable. For Oil Projects up to now the calculation of wellhead value did not include allowance for capital costs. For the Kutubu and Gobe oil projects, wellhead value was set at 93% of FOB export value. For gas projects, regulation for determination of wellhead value has been put in place. The regulation for oil wellhead value determination has yet to be set. 3.5 Development Levies Development levies are charged at the rate of 2% of wellhead value of all petroleum or gas produced out of a petroleum or gas project, and are calculated in the same manner as royalty, and are treated as a normal business expense and are therefore a tax deduction.

Development levies were introduced in the Oil and Gas Act 1998, and are applicable to future projects and to existing projects if a licence (PDL) is varied to establish a new development.

Development levies apply to Petroleum Development Licences and are payable to the project affected Provincial Governments via a State trust account from which the Provincial Government may make budget appropriations.

3.6 State Participation Pursuant the Oil and Gas Act the State has the right, but not the obligation, to acquire from the licensees up to a 22.5% interest in any petroleum project. The Petroleum Agreements provide that this option may be exercised at the time of grant of a petroleum development licence. The interest is acquired either directly by the State, a wholly owned company called the Mineral Resources Development Company Pty. Ltd. (MRDC) or a State nominee.

3.6.1 Acquisition Price

The price payable by the State is equal to the elected percentage (normally 22.5%, but may be smaller if the State elects to take a lesser interest) of the costs incurred in the 20 years prior to the grant of the petroleum development licence, including exploration expenditure anywhere in the underlying petroleum prospecting licence. The State or its nominee becomes a full joint venture participant, and (subject to the carry provisions referred to below) is liable for its share of all development and operating expenses.


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3.6.2 Obligation to Carry State

The Petroleum Agreements contain provisions, which oblige the licensees of a petroleum development licence other than the State or its nominee, where the State has exercised its option to acquire an interest, to carry the State or its nominee for both the initial acquisition cost and all subsequent development and operating costs. This carry is repaid out of production from the State’s interest (excluding the 2% landowner equity), which is foregone until the carry is repaid in full, with a commercial rate of interest.

3.6.3 Part of Equity Held for Landowners

The policy and law of the State is that, out of the State’s 22.5% equity entitlement, a 2% interest shall be provided to project area landowners without charge. This interest is held for the landowners by a trustee company, which becomes a full joint venture participant. This interest is unencumbered up to the commencement of commercial production, but thereafter the trustee is responsible for all capital and operating expenses attributable to the interest in question.

3.7 Value Added Tax (VAT) With the introduction of the Value Added Tax Act 1998, all previous local Sales Taxes and VAT as of 1st July 1999 effectively replaced most Customs Import Duties. Following a legal challenge in the country’s Supreme Court, which challenged the legitimacy of VAT, the distribution of VAT receipts to the Provinces has been changed. It is also proposed to change the name of VAT to GST – goods and services tax – similar to Australia. Value Added Tax is levied at the standard rate of 10%, and applies generally to all imports. However export activities are ‘zero-rated’ for VAT purposes. This means VAT is not payable on input purchases. Petroleum companies, since they export all their produce, are therefore not liable to pay VAT. Until recently, petroleum companies paid VAT on locally purchased goods and services but later claimed a credit or refund. Since 2001, however, no VAT needs to be paid up front. The fiscal regime applying to both petroleum and gas project is in most cases the same, as described above.

3.7.1 Gas Projects

In order for a project to attract gas fiscal terms, the developer must enter into an agreement, called a Gas Agreement, with the State. The Gas Agreement has the effect of applying the relevant provisions of the Income Tax Act to the project in question, and it will determine exactly how the regime is to apply (for example, the same petroleum fields may support both an oil project and a gas project, and the Gas Agreement would determine how the two regimes will apply to a single field).

The State may agree to enter into a Gas Agreement in relation to a project in different stages; at an early stage, to assure the licensee that gas fiscal terms will apply, thereby enabling it to market that resource with confidence in the fiscal regime; and immediately before project development, when the whole project structure is known.

The Gas Agreement will act as a complete replacement for a Petroleum Agreement in relation to the particular gas project.


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3.7.2 Stamp Duty The transfer of a petroleum licence, or an interest in a licence, is subject to stamp duty. A flat amount of stamp duty of K5, 000 is payable, plus K5, 000 for the cost of exploration expenditure transferred (known as information). Where the price paid exceeds the cost of exploration, 2% stamp duty is payable on the additional amount (over K100, 000). For example, in the case of development licences, additional capital expenditure would be mostly subject to 2% stamp duty. 3.7.3 Fiscal Stability Petroleum and gas projects may contain a clause ensuring that the fiscal terms in operation at the start of a contract will not be changed for 20 years or the duration of the financing period, whichever is less. However, from 2003 onwards, companies benefiting from fiscal stability terms will be subject to an additional 2% income tax.


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PART 4: PETROLEUM AGREEMENTS 4.1 Introduction A Petroleum Agreement may be executed by the State and the licensee prior to a project being developed, and will normally be executed prior to drilling the first exploration well. The Minister may require the execution of a Petroleum Agreement as a condition of a licence or a licence variation. The Petroleum Agreement contains the definition of the extent of a particular project and operations for that petroleum project, for the purpose of the Oil and Gas Act and any other law; the transfer and assignment of a State equity interest in that petroleum project to MRDC and any other matters relating to that petroleum project or those operations, which are agreed to by parties to such agreement. A Standard Petroleum Agreement has been developed as the model for this agreement. Some of its provisions can be varied in negotiations between the State and the licensee. An outline of the Standard Petroleum Agreement is given in the following sections. The Gas Agreement contains the definition of the extent of a particular project and operations for that gas project, for the purpose of the Oil and Gas Act and any other law; the transfer and assignment of a State equity interest in that gas project to MRDC and any other matters relating to that gas project or those operations, which are agreed to by parties to such agreement. 4.2 Terms of Standard Petroleum Agreement A copy of the current version of the Standard Petroleum Agreement can be obtained from the Petroleum Division of the Department. The following is a summary of some of the important terms: 4.2.1 Discoveries

In the event of a discovery the licensee will have not less than two years within which to carry out an appraisal programme on the discovery area. This programme will be in addition to the general work programme for the whole licence area.

4.2.2 Applications for Development

After the completion of the investigations and studies, the licensee has a minimum of three months (or longer with the Minister's permission) to apply for a petroleum development licence.

4.2.3 State Participation

The State has the right and option to acquire up to 22.5 percent interest in any petroleum development project. The purchase price is equal to the equivalent proportion of expenditure incurred by the licensee in the previous 11 years. The acquisition is completed through a nominee of the State, which then becomes liable for its proportionate share of all future expenditure on the project. However, the nominee is also entitled to the benefit of a carry on all expenditure (including the initial purchase cost) from the other participants, to be repaid (together with a


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commercial rate of interest) out of petroleum production attributable to the nominee’s share.

Further details of the financial obligations surrounding this acquisition are set out in Part 3, (Fiscal Regime – State Participation).

4.2.4 Landowner Equity

It is the State’s policy that, out of the 22.5% State participation, a 2% interest will be held for the benefit of project area landowners. This interest is provided free to landowners, unencumbered as of the commencement of commercial production. The development cost up to the first production is paid for by the State.

4.2.5 Ownership of Facilities

All facilities constructed by the developer are, unless otherwise specifically agreed by the State, to be paid for and owned by the developer.

At the end of a project, the State has the option to purchase the facilities from the developer at their tax written down value.

4.2.6 Import and Export

Developers are guaranteed the right of freedom to import all materials and things needed for petroleum operations, and to export petroleum. Exports are guaranteed to be free of any export duties. Developers are also guaranteed non-discrimination in import duties.

Further details of the import duties imposed on imports are set out in Part 3, (Fiscal Regime – Value Added Tax).

Developers may be subject to an obligation to supply petroleum to domestic consumers of such petroleum, subject to equivalence in price, and payment in the appropriate currency. Developers are guaranteed that they will not be penalised in any way by any obligation to sell petroleum domestically.

4.2.7 Currency and Exchange Control

There are detailed provisions governing currency transactions and exchange control. The activities of a petroleum licensee, even if the licensee is a foreign company, are regulated in the same way as if the licensee was a PNG person engaged in offshore transactions.

Proposals for financing a development project are approved by Bank of Papua New Guinea (BPNG), the central bank of Papua New Guinea. Flexibility exists, but generally debt: equity ratios cannot exceed 3: 1. BPNG is flexible in its treatment of different forms of capital as equity or debt.

Licensees are permitted to retain earnings in foreign currency offshore for the purpose of debt service, meet foreign currency liabilities, and for remittance of profits. Detailed reporting of foreign currency transactions is required.


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4.2.8 Domestic Requirements/Local Content

A developer is required to file and adhere to a training and localisation plan. Local employees must be given preference, subject to the availability of suitably qualified and experienced applicants. Where expatriate employees are required, the State guarantees the provision of appropriate visas.

Subject to equivalence in quality, availability and price, preference must be given to PNG suppliers in the acquisition of goods and services for petroleum projects.

Developers are also required to encourage and assist business development in PNG and the area of their projects.

4.2.9 General

Other terms include:

(i) Arbitration

Disputes under the Petroleum Agreement referred to arbitration are to be settled in accordance with UNCITRAL Arbitration Rules, in single judge arbitration in Singapore (except disputes as to the value of petroleum, which are subject to resolution before a single arbitrator in PNG under the Arbitration Act of PNG). UNCITRAL arbitration in Singapore applies also to any dispute between the Minister and an applicant for a PDL under the Oil & Gas Act as to whether the applicant’s proposals for development provide for optimum development of the petroleum pool in accordance with good oilfield practice; adequately provide for protection of the environment and the welfare of the people of the area; or are otherwise in the interest of the people of Papua New Guinea.

(ii) Applicable Law

The law of Papua New Guinea and applicable International Laws governs the agreement.

(iii) Termination

The agreement may be terminated only if the licence to which it relates has been cancelled. If a joint venture defaults or is in breach of an obligation, which is several and not joint interest of that joint venture may be assigned proportionately among the other joint venture partners.

(iv) Assignment

A licensee may assign its interest to other parties in the agreement, to affiliated companies, or, with the agreement of the other parties, to any other concern provided the assignee assumes the obligations of the assignor.


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PART 5: TRADITIONAL LAND OWNERSHIP AND LANDOWNER BENEFITS 5.1 Introduction Nearly all land in Papua New Guinea, particularly land outside urban areas, is held under customary title by the clans of people who traditionally have been recognised as the owners of the land. Customary law is part of the underlying law in PNG. The Constitution provides that statutory law will override customary law when customary law conflicts with the customary law. Thus customary ownership of land is recognised under PNG law, but the statute law clearly provides that ownership of minerals and petroleum in the ground is vested with the State.

In recognition of the important position of customary landowners in the areas of petroleum projects, the State has implemented a series of policies of providing various benefits and concessions to those landowners and others in the project area. The principal benefits are devolution of royalties and equity in projects, and business development opportunities. In addition, other grants are sometimes made available, and the State has introduced a tax credit scheme, whereby developers can construct infrastructure of benefit to the region and the cost can be treated as payment of tax. 5.2 Royalty Benefit Royalty at 2% of the wellhead value of petroleum production is presently payable by petroleum producers to the State. The Oil & Gas Act 1998 now stipulates that, for all new projects and in the case where an existing PDL is varied, the State would grant these royalty payments as benefits to be shared between the project area landowners, the affected Local-Level Governments, and affected Provincial Governments of the project in proportions agreed by them in a development agreement.

The Oil and Gas Act govern royalty distributions. A substantial portion of these benefits are paid into a trust account and invested for future generations. 5.3 Project Equity Benefit It is the policy of the State that where the State does acquire a participating interest in a petroleum project, 2% equity in that project will be granted to the affected landowners and affected Local Level Government through a trustee, free of any liabilities as at the commencement of commercial production. The cost of acquiring the participating interest in the petroleum projects for the purposes of the equity benefit and development attributable to that participating interest up until the commencement of commercial production of petroleum from that petroleum project shall be borne by the State.

The net benefits from this 2% free equity (after royalties, budgeted expenditure, cash calls, marketing fees, contribution to an abandonment fund, etc.) is paid directly to incorporated landowner groups on behalf of landowners. At least 30% of the equity benefit is required for a payment into a trust account and invested for future generations.

The parties entitled to participate in equity benefits are the clans, which are the traditional owners of the land in the area of the PDL or PDLs under which the project is developed, as well as those who are the traditional owners of other land on which


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project facilities are constructed. This will include the clans over whose land any associated pipeline is constructed. 5.4 Business Development Opportunities

An important part of the benefits package provided to project area landowners is business development opportunities. It is the policy of the State, embodied in the Oil and Gas Act and the Petroleum Agreement that, subject to equivalence in quality, price and availability, preference will be given in procurement for the project to PNG suppliers of goods and services, in particular suppliers from the project area. Consequently, project developers put considerable efforts into assisting project area landowners in developing businesses to supply goods or services to the project. This is not limited to landowners in the licence area, but can spread to landowners in the surrounding regions.

Developers are also encouraged to provide assistance to locals in developing businesses unrelated to the project, which will be sustainable long after the project ends production and has been abandoned. The provision relating to business development opportunities are contained in Section129 of the Oil and Gas Act 1998.

5.6 Tax Credit Scheme The Government of Papua New Guinea has implemented a tax credit scheme, whereby project developers may spend up to 0.75% (reduced from 2% in January 2001) of their assessable income. The payment of the costs of such infrastructure projects is treated as income tax paid. In 2002 the law was amended to allow for 1.5% of assessable income to be allowed, in 2002, as tax credit expenditure for repair work on the Highlands Highway.

The Minister shall establish an Expenditure Implementation Committee in respect of each petroleum project. The Committee will be responsible for monitoring budgets and timetables for construction and implementation of grant and benefit expenditure on behalf of affected Local Level Government and affected Provincial Government and approve such expenditures. It will also monitor expenditure made pursuant to Section 219 of the Income Tax Act 1959 to ensure that project funded complies with the development plans submitted by the relevant Local Level Government or Provincial Government. The committee is to monitor the program of ongoing projects for expenditure of monies and ensure licensees undertake projects approved by the Expenditure Implementation Committee of the project in question.


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PART 6: ENVIRONMENTAL GUIDELINES AND REQUIREMENTS Petroleum activities are guided, among others, by two pieces of environmental Legislation, the Environment Act 2000 and Oil and Gas Act 1998. The petroleum licensees are required to comply with environmental guidelines enshrined in these legislative documents. 6.1 Environment Act 2000 Requirements

The environment Act 2000 requirements include environmental permits, registration of intention to carry out preparatory work and environment impact assessment. 6.1.1 Environmental Permits

The Environment Act 2000 prescribes three different levels of activities, which may be classified as Level 1,2 and 3 Activities and Existing Activities. Activities that involve (a) matter of national importance and (b) may result in serious environment harm are classified as Level 3 activities. Those activities that fall below Level 3 criteria may be classified as Level 1 or 2 depending on the Environmental Impact Assessments. Permit is required for a level 2 or 3 activity, or a change in process, or expansion of works or plant in relation to an existing activity such that a level 2 or level 3 activity is carried out, a permit is not required for level 1 and existing activities. However, the Director for Environment and Conservation may issue notice if it is required. Failure to obtain a permit would incur the following penalties. A Corporation will be fined a penalty of a fine not exceeding K100, 000.00. If other than a Corporation, it will be fined a penalty of a fine not exceeding K50, 000.00 or imprisonment for a term not exceeding two years, or both. A default penalty of a fine not exceeding K5, 000.00 will be imposed. 6.1.2 Registration Of Intention to Carry Out Preparatory Work

Registration of intention to carry out preparatory work will be done by a person who proposes to carry out a level 2 or level 3 activity; or proposes to change the nature of a level 2 activity such that it becomes a level 3 activity, should register that intention in writing to the Director of Environment and Conservation one month prior to the commencement of the any preparatory work. Failure in registering intention is an offence. A Corporation is subject to a fine not exceeding K20, 000.00. If other than a Corporation, it is liable to a fine not exceeding K10, 000.00. 6.1.3 Environmental Impact Assessment The Director of Environment and Conservation may notify the proponent to carry out an Environmental Impact Assessment (EIA) in relation to the proposed activity. An Environmental Impact Assessment shall involve the following stages;

(i) Submission of an Inception Report, setting out the issues to be covered in

the Environmental Impact Statement; (ii) Submission of an Environmental Impact Statement setting out the physical

and social environmental impacts which are likely to result from the carrying out of the activity

(iii) Assessment and public review of the Environmental Impact Statement; (iv) Acceptance of the Environmental Impact Statement by the Director; (v) Referral of the Environmental Impact Statement, assessment report and

other material to the Environment Council


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(vi) Recommendation by the Council to the Minister; (vii) The Minister acts on the Councils’ recommendation and grants an approval

in principle An application for an environment permit may not be accepted in relation to the activity unless an environmental impact assessment has been completed, and that the Minister has given an approval in principle to the proposed activity. 6.1 Environment Guidelines Under Oil and Gas Act 1998 Defined environmental guidelines are set out by the Oil and Gas Act 1998 in relation to petroleum activities by tenement holders. 6.2.1 Procedures Governing Discoveries Where a location has been declared, the Minister may direct the licensee to carry out such investigations and studies, as the Minister thinks proper. Such investigations and studies may include physical impact studies into the possible effects of that industry on the environment and the tenement holder shall furnish to the Minister, within the specified time frame, such reports, analyses and data resulting from the investigations and studies. 6.2.2 Project Consultation

The Applicant or intending applicant has to submit to the Minister for Petroleum and Energy and to the Minister responsible for environmental matters documents such as an Environmental Inception Report (EIR) and an Environmental Impact Statement (EIS) as part of the EIA process required under the Environment Act 2000.

6.2.3 Licences

6.2.3.1 Petroleum Development Licences

Where an applicant has properly applied for a Petroleum Development License the Minister will inform the applicant to lodge a security deposit for compliance with conditions relating to the protection and restoration of the environment and the Provisions of Oil and Gas Act. Any requirement in any law relating to protection and restoration of the environment, or any conditions imposed on the licensee under any such law and any condition relating to the physical planning of the area. The Minister shall approve the proposals and grant the applicant a licence where he is satisfied, having considered these proposals, any further submissions of information and a report from the Board (Petroleum Advisory Board) that provide adequately for the protection of the Environment and the welfare of the people of the area.

6.2.3.2 Pipeline Licences

A pipeline licence may be granted subject to such licence conditions as the Minister thinks fit and satisfies in the license.


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6.2.3.4 Petroleum Processing Facility Licences An application for the grant of a Petroleum Processing facility Licence shall be

accompanied by particulars of Environmental Monitoring Systems, Waste Disposal Procedures and the results of Environmental Studies.

6.2.4 Rights in Respect of Land and Property

Tenement Holder has rights in respect of land and property. Subject to the Environment Act 2000, the licensee can take and divert water from any lake, stream or watercourse in the licence area and cut and use the timber in the licence area for construction work within the area. The tenement holder has the right to remove any stone, clay or gravel in the licence area for or in connection with building and construction work within the licence area. 6.2.4.1 Rights of Pipeline Licensees

The pipeline licensee has the right to construct roads to give adequate access to the petroleum processing facility and cut and use timber for building or construction work related to the facility. The licensee has the right to remove any stone, clay or gravel for or in connection with building or construction work related to the facility. 6.2.4.2 Additional Rights of Entry If an emergency exists in an operation area, which threatens health, safety, environment or state’s petroleum resources; the licensee may enter lands not held under his licence area without authorization to deal with the emergency, but must not exceed 72 hours after first entering. A licensee is however, liable to pay compensation for the deprivation of the use and enjoyment of the surface of the land or any rights customarily associated with it, except where there is a reservation in favour of the State and the damage to the surface of the land or any improvements on it. This also includes damage to any trees, fish or animals and any other damage consequential on the licensee’s use or occupation of the land.

6.2.5 Work Practices A tenement holder is to adhere to work practices including control the flow and prevent the escape in the licence area of petroleum or water, except in accordance with a permit or licence issued under a law regulating the discharge or release of petroleum, petroleum products or water; and prevent the escape in the licence area of any mixture of water or drilling fluid and petroleum or any other matter The licensee must prevent the pollution of any water-well, spring, river, lake, reservoir, estuary, harbour or area of sea by the escape of petroleum, salt water, drilling fluid, chemical additive or any other waste product or effluent. It is required to furnish to the Director, prior to the drilling of any well, a detailed report on the techniques to be employed, the material to be used and the safety measures to be employed, in the drilling of the well. A pipeline licensee must prevent the escape of petroleum or petroleum products or water from the pipeline, except in accordance with a permit or licence issued under a law regulating the discharge or release of petroleum products or water.


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A petroleum processing facility licensee must prevent the escape of petroleum or petroleum products or water from the facility, except in accordance with a permit or licence issued under a law regulating the discharge or release of petroleum, petroleum products or water. 6.2.6 Surrender of Licences Consent to a surrender of a licence will be given by the Minister if he is satisfied that the licensee has complied with the conditions specified in the licence and with the provisions of Oil and Gas Act and has plugged or closed off all wells made in that area, and made arrangements with respect to termination of operations of the pipeline or petroleum processing facility. The licensee has removed all properties and any wastes deposited in that area by the licensee or any person on his behalf or made arrangements with respect to that property or waste and made satisfactory provision for, site reclamation, conservation and protection of the natural resources in that area. 6.3 Removal of Property, etc; by the Licensee, etc. Prior to abandonment of a well, a tenement holder is to request the Director to approve a program for the abandonment which includes removal of equipment, plugging the well bore, and reclaiming the well site and; complete logging, testing and submission of information and relevant evaluations and conduct abandonment operations according to the manner prescribed by regulations. Where any license has been cancelled or expired, the Minister may direct the person who was/is the licensee to make provision, to the Minister’s satisfaction, for the conservation and protection of the natural resources in that area. 6.4 Drilling for Discovery of Water Drilling for water anywhere in the Licence area will be done as determined by the Minister or in accordance with the Environment Act 2000 6.5 Regulations The Head of State, acting on advice, may make regulations not inconsistent with The Oil and Gas Act 1998. 6.6 Health Safety and Environment Legislations Petroleum operations in the country are also guided by certain legislations, which the petroleum licensees are required to comply with. These include; • Physical Planning Act (1989) • Fauna (protection and Control) Act (Chapter 154) • Industrial Safety, Health and Welfare Act (Chapter 175) • National Institute of Standards and Industrial Technology Act 1993 • Inflammable Liquid Act (Chapter 311)

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